In order to maximize the production of gasoline, atmospheric distillation residue is typically subjected to vacuum distillation and the vacuum gas oil is cracked in a fluid catalytic cracking (FCC) unit or a hydrocracking unit operation to produce more gasoline-range products. FCC naphtha, coking unit or coker naphthas are commonly referred to as cracked naphtha and typically contain significant amounts of aromatics and olefins. Some refiners recover the cracked naphtha entirely for gasoline production and other refiners subject a portion of the cracked naphtha to aromatic extraction and utilize the remainder for gasoline production. A number of prior art publications and patents disclose processes for extracting the aromatics including benzene, toluene and xylene, commonly referred to as BTX.
Cracked naphtha from FCC or coking units is typically high in olefins and aromatics, but also high in sulfur- and nitrogen-containing compounds. FCC naphtha is used commercially for gasoline blending after hydrotreating, and the prior art includes a number of proposals for producing BTX and aromatics from this feedstock.
The fractionation of FCC naphtha on a limited scale has been disclosed in the prior art. A process in which the naphtha is split into at least two fractions is described in U.S. Pat. No. 9,434,894 (Mehlberg et al). This prior art process is schematically illustrated in FIG. 1 where the system (100) includes an FCC unit (110) producing an FCC naphtha stream (112) that is passed to splitter (120) from which the lightest fraction (122) containing C5 and C6 hydrocarbons and is sent directly to the gasoline blending pool. The second fraction (124), containing at least C6-C9 hydrocarbons is passed to a selective hydrogenation processing unit (130) to remove mercaptans and convert diolefins to mono-olefins (132) which are then passed to an aromatics extraction unit (150) to remove a portion or all of the aromatics from the selectively hydrogenated fraction. The aromatic-lean raffinate stream (152) from the aromatic extraction unit (150) that is rich in olefins and paraffins is sent to the gasoline blending pool (160). The heaviest fraction (126) from the FCC naphtha splitter (120) containing C10+ hydrocarbons is passed to hydrotreating unit (140) and the hydrotreated stream is sent to the gasoline blending pool.
Another prior art process disclosed in U.S. Pat. No. 5,685,972 to Timken et al is shown in the simplified schematic illustration of FIG. 2 where the system (200) includes an FCC unit (210) producing an FCC naphtha stream (212) that passes to splitter (220) that splits the FCC naphtha stream into two streams, one (222) having a boiling point of less than 170° F. and the second (224) having a boiling point greater than 170° F. (˜77° C.). The lower boiling lighter fraction (222) is sent directly to the gasoline blending pool (270) while the heavier fraction (224) is passed to hydrodesulfurization unit ((230) and, optionally, passed to an octane recovery reactor (240) containing zeolite catalyst or, alternatively, transferred to distillation unit (250) for recovery of a 170° to 300° F. (˜77° C. to ˜150° C.) fraction (252) that is passed to BTX extraction unit (260), and a 300° F.+ (˜149° C.) fraction (254) that is sent to the gasoline blending pool (270). The raffinate stream (264) following BTX extraction is also sent to the gasoline blending pool (270).
Although the prior art processes described above provide some advantages in processing FCC naphtha streams, additional problems are faced by refiners utilizing existing FCC units and the need exists for an improved process and system for increasing the efficiency of recovering gasoline blending pool components from FCC naphtha streams, and to thereby increase the overall value of the FCC naphtha by improving the quality and performance characteristics of the products recovered.